Method and Apparatus for Measurement of Individual Components of a Multiphase Fluid

ABSTRACT

A method for determining the flow rates of a multi-component mixture in a pipe including a gas phase and a liquid phase, the method comprising the following steps: a. the flow rates of the individual components of the multi-component mixture are measured, b. the Reynolds number of the multi-component mixture is measured separately from the flow rate measurements, and c. based on the result from step a and b, a more accurate flow-rate of the individual components of the multi-component mixture is calculated. An apparatus for performing the method is also disclosed.

The present invention relates to a method and flow meter for determiningthe flow rates of individual components of a multiphase fluid, asdefined in the preambles of claims 1 and 8 respectively.

A flowing mixture of oil, water and gas is a common occurrence in theoil industry being a product of an unprocessed well stream. Such a wellstream is often referred to as a multiphase mixture where oil, water andgas are referred to as individual phases or fractions. When the amountof gas (GVF) is greater than 90% of the total volume in the pipe, thewell is often referred to as a wetgas well. For clarification purposes,multiphase flow in the context of this patent application covers thefull component fraction range and hence includes both wetgas andmultiphase flow conditions.

The oil wells can also be classified as light or heavy oil. A condensateis a very light oil where the density typically is less than 700 kg/m3and the viscosity typically is less than 1 cP. A light crude oil typicalhas a density in the range 700-900 kg/m3 and a viscosity in the range1-100 cP. A heavy oil is more viscous and has a higher density. Typicalviscosity range is 100-10.000 cP and density in the range 850-1200kg/m3. Water typically has a density in the range 1000-1200 kg/m3 with aviscosity in the range 0.5-2 cP.

In order to optimize the production and life of an oil/gas field,operators need to be able to regularly monitor the output of each wellin the field. The conventional way of doing this is to use a testseparator. Test separators are expensive, occupy valuable space on aproduction platform, and require a long time to monitor each wellbecause of the stabilized flow conditions required. In addition, testseparators are only moderately accurate (typically ±5 to 10% of eachphase flow rate) and cannot be used for continuous well monitoring. Mostseparators use the density difference between oil, water and gas toseparate the three phases, either by using the earth gravity in a tankor by using a cyclone principle.

These techniques are well known. However, if the density of the oil andwater is of similar magnitude and the viscosity of the oil is high,gravity or cyclone based separators are not able to provide properseparation of the oil and water phase, which may lead to largemeasurement errors for the test separator.

A three-phase flow meter could be used in the first instance instead ofa test separator and in the long term as a permanent installation oneach well. There are several techniques and known instruments formeasuring multiphase flow, as will be further described below. Suchinstruments need to be reasonably accurate (typically better than ±5% ofrate for each phase), non-intrusive, reliable, flow regime independentand provide accurate measurements over the full component fractionrange. Such an arrangement would save the loss in production normallyassociated with well testing. Such loss is estimated to be approximately2% for a typical offshore installation. Allocation metering is neededwhen a common pipeline is used to transport the output from a number ofwells owned by different companies to a processing facility. This iscurrently achieved by passing the output of each well through a testseparator before entering the common pipeline. However, in addition tothe disadvantages of the test separator described above, dedicated testpipelines to each well are also required. A permanently installedthree-phase flow meter would offer significant advantages for allocationmetering.

Other devises for measurement of flow rates of a multiphase mixture maybe based on measurement of differential pressures across a restrictionin the pipe such as a Venturi tube, Orifice plate, v-Cone, Dall tube,flow mixer or Wedge tube. Examples of such devices can be found in U.S.Pat. No. 4,638,672, U.S. Pat. No. 4,974,452, U.S. Pat. No. 6,332,111,U.S. Pat. No. 6,335,959, U.S. Pat. No. 6,378,380, U.S. Pat. No.6,755,086, U.S. Pat. No. 6,898,986, U.S. Pat. No. 6,993,979, U.S. Pat.No. 5,135,684, WO 00/45133 and WO03/034051.

In fact, any restriction in the pipe will result in a change in thevelocity of the multiphase mixture and introduce a pressure drop acrossthe restriction. Based on the theory of fluid dynamics, the square rootof the pressure drop is proportional to the total mass flow rate in thepipe. A venturi tube, dall tube, orifice plate and v-cone are examplesof a structure where the pipe diameter is gradually reduced into asection of the pipe with a smaller diameter. The smaller section may beshort or a relative long section. For a venturi, the diameter isgradually expanded to the original size of the pipe whereas the dalltube and orifice plate has a more abrupt transition after the narrowsection. Mass flow measurements with such structures are well known anddescribed in standards, patents and other publications. One suchstandard is the ISO standard 5167 “Measurement of fluid flow by means ofpressure differential devices inserted in circular cross-sectionconduits running full” part 1—general principles and part 4—venturitubes.

According to ISO 5167-1, the mass flow rate can be calculated as:

$\begin{matrix}{{Qm} = {\frac{C}{\sqrt{1 - \beta^{4}}}\frac{\pi}{4}d^{2}\sqrt{2{\rho\Delta}\; p}}} & {{Equation}\mspace{14mu} 1}\end{matrix}$

-   -   where:        -   Qm=Total mass flow rate        -   C=Discharge coefficient        -   β=Diameter ratio between venturi throat and pipe        -   d=Diameter of venturi throat        -   Δp=Measured pressure drop between inlet and venturi throat            -   ρ=Density of the multiphase mixture

The adoption of venturi tubes for multiphase and wetgas flow conditionsare further described in “Design of a flow metering process fortwo-phase dispersed flows”, Int. J. Multiphase Flow vol 22, No 4, pp713-732, “A study of the performance of Venturi meters in multiphaseflow”, by Hall, Reader-Harris, and Millington, 2^(nd) North AmericanConference on Multiphase Technology and “Liquid Correction of VenturiMeter Readings in Wet Gas Flow”, by Rick de Leeuw, North Sea FlowMeasurement Workshop—1997.

The discharge coefficient C is a calibration constant for the venturi,which can be found either by calibrating the venturi on a fluid such aswater, oil or gas or calculated based on the mechanical dimensions andproperties of the venturi. These techniques are well known and notdescribed any further.

It is also well known that the discharge coefficient for all devicesbased on measurement of differential pressure across a restriction inthe pipe is a function of the Reynolds number of the multiphase fluid(e.g. SPE 63118 —Qualification of a Nonintrusive Multiphase Flow Meterin Viscous Flow by D. I Atkinson et al (2000)—FIG. 5). In fluidmechanics, the Reynolds number (Re) is a dimensionless number that givesa measure of the ratio of inertial forces to viscous forces andconsequently quantifies the relative importance of these two types offorces for given flow conditions. For a flow in pipes, the Reynoldsnumber (Re) is defined as:

$\begin{matrix}{{Re} = \frac{{VD}\; \rho}{\mu}} & {{Equation}\mspace{14mu} 0}\end{matrix}$

where V is the velocity of the fluid in the pipe, D is the pipediameter, ρ is the density of the fluid in the pipe and μ is theviscosity of the fluid in the pipe.

In the following section, the venturi is used as an example. However,the same principles apply also for other differential based flow devicessuch as a V-cone, Dall Tube and Orifice Plate.

When the Reynolds number is high, which is typical for most multiphaseapplications with gas, water and condensate/light oil, the dischargecoefficient is typical in the range 0.98-1.0. For these applications, afixed discharge coefficient in the range 0.98-1.0 can easily be used forthe venturi without introducing any significant errors in thecalculation of the flow rates.

However, for multiphase applications where the oil viscosity issignificantly higher than water (e.g. >10 cP), the Reynolds number couldbe reduced such that the venturi operates in an area where the dischargecoefficient is significantly lower than 1.0 and also varies with theReynolds number.

FIG. 10 shows examples of how the venturi discharge coefficient (20/22)changes as a function of the Reynolds number (21). From FIG. 10 it isseen that the discharge coefficient for this particularly venturichanges from 0.6 to 1.0 when the Reynolds number changes from 70 to1.000.000. For heavy oil applications the Reynolds number may be below10 giving a venturi discharge coefficient in the range 0.2-0.3.

Hence, any multiphase meter which uses a differential pressure baseddevice to determine the flow rate of the multiphase fluid mixture, needsto determine the Reynolds number of the multiphase fluid in order toprovide reliable measurement of the flow rate. This is particularlyimportant for heavy oil applications since the variation in the Reynoldsnumber then is significant.

There are many devices and methods for three-phase flow measurements.There are many ways that these flow devices can be categorized and oneway is to divide them into three categories depending on which type ofliquid emulsions the meter can handle. The first category ismethods/devices that covers oil continuous flow conditions only, asecond category are methods/devices that covers water continuousconditions only and a third category are methods that covers both oiland water continuous flow conditions. Oil continuous conditions meansthat the water is dispersed in the oil as droplets such that oil becomesthe continuous medium in the liquid phase. The liquid may be dispersedas droplets in the gas or the gas may be dispersed as bubbles in theliquid phase; however, the liquid in the above example is still oilcontinuous. Similarly, the liquid is water continuous when the oil isdispersed as droplets in the water phase. A water/oil mixture is alsocommonly referred to as an emulsion and similarly the emulsion may beeither oil or water continuous. For each category there may also beseveral sub categories such as tomographic/non-tomographic methods anddevices, and intrusive/non-intrusive methods and devices etc.

The water cut, or water liquid ratio (WLR), is defined as the amount ofwater (percentage) in the liquid emulsion (e.g. oil+water) of amultiphase mixture (e.g. oil+water+gas). For WLRs below 20%, the liquidemulsion is in general oil continuous and similarly for WLRs above 80%,the liquid emulsion is normally water continuous. In a certain WLRregion the liquid emulsion can be either water continuous or oilcontinuous. This region is commonly referred to as the switching regionsince the liquid may change from oil continuous to water continuous orvice versa. Light crude oil typical has a switching region for WLRs inthe range from 35% to 70% whereas heavy oil or viscous oils typical havea switching region from in the WLR range from 20% to 80%.

The liquid phase has quite different characteristics depending whateverthe liquid emulsion type is oil or water continuous. If the water issaline, an oil continuous emulsion is non-conducting whereas a watercontinuous emulsion is conductive. If the water is fresh there is nosignificant difference in the conductivity of the emulsion; however, thedielectric constant of the emulsion is quite different in the two casesirrespective of the salinity of the water as shown in FIG. 9. Thedielectric constant of an oil continuous emulsion 18 is plotted in FIG.9 for a water liquid ratio of 0-100% on the same graph as the dielectricconstant of a water continuous emulsion 16 using the Bruggeman mixinglaw as described in “Electromagnetic mixing formulas andapplications—IEE Electromagnetic Wave Series 47” by Ari Shivola forcalculating the dielectric constant of the emulsion. In this example,the oil has a dielectric constant of 2.0 and water has a dielectricconstant of 80 (fresh water). As seen from the graph, the relativedifference is particularly large in the switching region indicated withan arrow 13.

The viscosity of the liquid emulsion also has a similar behavior asshown in FIG. 8. The viscosity of an oil continuous emulsion 15 isplotted as a function of WLR on the same graph as the viscosity of awater continuous liquid emulsion 13. The viscosity of an oil/wateremulsion is calculated as described in “A study of the performance ofVenturi meters in multiphase flow”, by Hall, Reader-Harris, andMillington, 2^(nd) North American Conference on Multiphase Technology.In this example an oil viscosity of 20 cP (typical light oil) and awater viscosity of 1.5 cP (saline water) are used. As seen from thegraph, the relative difference in the liquid viscosity is particularlylarge in the switching region indicated with an arrow 14. Since theviscosity of the oil is also temperature dependent, the oil viscosityalso needs to be corrected for the temperature effect. FIG. 2 in thepublication “Viscosity of oil and water mixtures”, by A. E Corlett etal, BHR group Multiphase workshop 1999, shows an example of thetemperature effect of the oil viscosity. This figure is for simplicityincluded as FIG. 11. For water continuous flow conditions (24), theviscosity is typically below 0.02 Pa*s (e.g. 2 cP). The switching regionbetween oil and water continuous appears in the water fraction range40-60% for this particular oil. For a temperature of 40° C., the liquidemulsion viscosity is in the range 0.01-0.025 Pa*s (10-25 cP) when thewater fraction changes from 0-40%. However, for a temperature of 15° C.,the liquid viscosity is in the range 0.04-0.07 Pa*s (40-70 cP) when thewater fraction is in the range 0-40%. Hence, a change in temperature of25° C. changes the liquid viscosity by 180% in this case.

Hence, in order to be able to calculate the liquid viscosity of anoil/water emulsion, it is important to know the oil viscosity and thewater viscosity in addition to the emulsion type (oil or watercontinuous). Since the oil viscosity is also a function of thetemperature, it is also important to know how the oil viscosity changesas a function of temperature. In addition, it is also necessary to knowhow the amount of water modifies the viscosity of an oil continuousemulsion. The viscosity difference between an oil and water continuousemulsion is particularly large for heavy oil conditions, where theviscosity for an oil continuous emulsion may be in the range3.000-10.000 cP, whereas the viscosity of a water continuous emulsionmay be less than 2 cP.

In field applications where the oil viscosity is high (typically above100 cP), the oil viscosity may change over time and is also difficult topredict as a function of temperature. For multiphase applications wherethe oil viscosity is significant higher than the water viscosity and adifferential pressure device, such as a venturi, is used to determinethe mass (and volume) flow rate of the fluid mixture, it is thereforeimportant to know whether the emulsion type is oil or water continuous,WLR and viscosity of the oil such that the correct venturi dischargecoefficient can be applied. Without such knowledge, the liquid and gasflow rate may easily contain measurement errors which are in the rangeof 10-300% depending on the viscosity of the oil.

One way to identify whether the emulsion is oil or water continuous isto perform laboratory experiments with particular oil and water for thefield, in order to determine when the oil/water mixture changes from oilto water continuous and vice versa as a function of the measured averageWLR. The problem with this method is that the WLR limit for change tooil and water continuous, and vice versa, will be highly temperature andflow rate dependent, and field experience with multiphase meters haveshown that it is not practical to use such a method since the WLR rangefor switching between oil and water continuous will contain largevariations even if the average WLR is known.

The present invention overcomes this weakness with existing multiphaseflow meters which are based on a venturi or other differential pressuredevice (such as a V-cone or Dall Tube) for determining the mass andvolume flow rate. The present invention performs a dedicated measurementin order to determine the Reynolds number of the multiphase mixture. Themeasured Reynolds number is then used to calculate the correct dischargecoefficient for a differential pressure based flow meter such as aVenturi, V-cone, Wedge meter or Dall Tube.

The invention can be used in combination with any differential basedmultiphase flow meter such that the multiphase meter can obtain acorrect discharge coefficient despite large variation in Reynolds numbercaused changes in the oil viscosity, WLR or emulsion type.

In a preferred embodiment of the invention an emulsion classificationmeasurement can also be used in order to determine the oil viscosity.When the Reynolds number is known, together with the WLR, the oilviscosity can be calculated provided that the emulsion type is oilcontinuous. This is possible since the Reynolds number is highlydependent on the oil viscosity for an oil continuous liquid emulsionwhereas the oil viscosity virtually has no impact on the Reynolds numberwhen the emulsion is water continuous. Hence, for an oil continuousemulsion, the oil viscosity can be determined. Oil-fields which areproducing heavy oil frequently use a light oil (called diluent) toreduce the viscosity of the oil. The diluent is mixed with the heavy oilin the reservoir to make it easier to produce the oil (a light oil withlow viscosity is easier to produce compared to a heavy oil). The diluenttypical has a very low viscosity (less than 10 cP) whereas the heavy oiltypically has a high viscosity (>1000 cP). Hence, when the oil viscosityof the multiphase fluid can be determined by the multiphase meter, thisinformation can then be used to determine the ratio between reservoiroil and diluent oil which is an important control parameter in order tooptimize production and recovery for heavy oil fields.

Multiphase flow meter which uses a differential pressure device todetermine the flow rate are well known in prior art. Examples of suchdevices can be found in U.S. Pat. No. 4,638,672, U.S. Pat. No.4,974,452, U.S. Pat. No. 6,332,111, U.S. Pat. No. 6,335,959, U.S. Pat.No. 6,378,380, U.S. Pat. No. 6,755,086, U.S. Pat. No. 6,898,986, U.S.Pat. No. 6,993,979, U.S. Pat. No. 5,135,684, U.S. Pat. No. 6,935,189,U.S. Pat. No. 7,624,652, WO 00/45133, WO03/034051, WO 02/44664.

Common to all these devices is that they are not able to determine theReynolds number of the multiphase mixture. As a consequence, the devicesare not able to perform reliable measurement of the multiphase fluid ifthe oil viscosity is high, particular for applications where theemulsion type is changing from water continuous to oil continuous.Similarly, these devices are not able to perform reliable measurementsfor heavy oil applications where the oil viscosity may vary over a broadrange due to variation in the content of the diluent oil, due naturalvariations in the oil viscosity in the reservoir or due to comingling ofwells with different oil viscosities.

Devices for measurement of fluid viscosity and/or Reynolds number arealso commonly known. Examples of such devices are found in U.S. Pat. No.8,353,220 and U.S. Pat. No. 5,661,232, based on a coriolis type flowmeter. Another commonly used device for performing viscosity measurementare devices based on a vibrating element which is inserted into theflow. Examples of such devices can be found in U.S. Pat. No. 8,316,722and U.S. Pat. No. 7,325,461, which are based on electronic drivenvibrating measurement transducers. Yet another type is based on vortexsensors such as U.S. Pat. No. 8,161,801.

Viscosity sensors based on coriolis type flow meter and mechanicalvibrating elements are not suited for measurement of the liquidviscosity of multiphase fluids containing gas since the gas will have alarge impact on the mechanical resonance frequency and may even preventthe mechanical device from resonating. Coriolis type flow meters andvibrating elements are also known to be fragile devices which are notwell suited for the harsh environment in an unprocessed well stream ofoil, water and gas. Unprocessed well stream may also contain sand whichcan cause damage to intrusive devices such as a vibrating mechanicalelement or vortex sensor.

A vibrating element could be used in connection with a multiphase meterif it is installed in such a way that the gas content around thevibrating element is close to zero. By installing the vibrating elementin a horizontal or vertical blind Tee of the pipe, the gas content maybe low enough for performing reliable measurements. However, then thefluid in the blind Tee may not be representative for the liquid in thepipe and hence the viscosity measurement will contain a largeuncertainty if there is variation in the liquid phase (e.g. variation inthe WLR or oil type).

It is the purpose of this invention to overcome the above mentionedlimitations of existing solutions.

It is the purpose of this invention to perform accurate measurements ofthe Reynolds number of a multiphase mixture containing gas.

It is the purpose of this invention to determine the dischargecoefficient of differential based flow device as a function of themeasured Reynolds number of the multiphase mixture.

It is the purpose of the invention to determine of the oil viscosity ofa multiphase mixture containing oil, water and gas.

It is the purpose of this invention to determine the diluent (light oil)and heavy oil component of a multiphase stream containing heavy oil,diluent, gas and water

It is the purpose of the invention to provide a non-intrusive device forperforming the measurements.

It is the purpose of the invention to provide a compact mechanicalstructure for performing the measurements.

These purposes are obtained according to the invention by a methodcomprising the following steps:

-   -   a. the flow rates of the individual components of the        multi-component mixture are measured,    -   b. the Reynolds number of the multi-component mixture is        measured, and    -   c. based on the result from step a and b, a more accurate        flow-rate of the individual components of the multi-component        mixture is calculated.

The apparatus according to the invention is further characterized by thefeatures as defined in the independent claim 8.

Dependent claims 2-7 and 9-14 define preferred embodiments of theinvention.

The present invention is based on measurement of the Reynolds numberbased on measurement of the pressure drop across the longitudinal partof a pipe section with known wall roughness, typically larger than theroughness of the surrounding pipe work including the multiphase meter.The wall roughness should be large enough such that the flow isturbulent even for low Reynolds numbers. A wall roughness greater than0.05 is sufficient for most applications. The wall roughness is heredefined as the roughness of pipe wall relative to the pipe diameter. Bymeasuring the pressure drop across the pipe section with the large wallroughness, the Reynolds number of the fluid flowing in the pipe sectioncan be determined provided that the velocity and density of themultiphase fluid is known.

The velocity and density of the multiphase fluid is determined by amultiphase flow meter. A multiphase flow meter based on a differentialpressure flow device is particularly suited for this invention since theReynolds number is needed for these devices in order to determinedischarge coefficient of the flow meter. Example of dP based multiphaseflow meters are Venturi, Dall Tube, V-Cone, Wedge and Orifice. Amultiphase meter is also suited to measure the fractions of themultiphase mixture. The multiphase meter may be based on a tomographicmeasurement principle where the liquid distribution in the pipe crosssection also can be determined or it may be based on non-tomographicmeasurement principle assuming that the multiphase mixture is evenlydistributed in the cross section of the pipe. Example of a tomographicmeasurement principle which can be used to determine the velocity anddensity is disclosed in U.S. Pat. No. 7,624,652.

The most common multiphase meters assume a homogeneous mixture of oil,water and gas in the cross section of the pipe. In order to determinethe individual fractions of a multi-component mixture of threecomponents such as gas, water and crude oil, it is then sufficient toperform measurement of two independent physical properties related tothe components of the mixture since the sum of the fractions isoccupying 100% of the pipe cross section, and can be used as the thirdequation.

Examples of combinations suited for measurement of fractions of amultiphase mixture are permittivity measurement in combination withdensity measurement, conductivity measurement in combination withdensity measurement or two mass absorption measurements at two differentenergy levels. The permittivity measurement may be based on any knownprinciple. The most common one are either based on microwave sensorprinciples or capacitance sensor principles. In order to calculate thefractions of the components, the corresponding physical properties foreach of the components needs to be known. E.g., when permittivity anddensity measurement are used to measure the permittivity and density ofa multiphase mixture containing gas, water and oil, the permittivity anddensity of the gas, water and oil needs to be known in order tocalculate the volume fractions of gas, water and oil in the pipe. Thesemeasurement principles for multiphase measurement are well known anddescribed in many of the references already cited in this document. Theprinciples are also well known to the industry and described in Handbookof Multiphase Flow Metering (2005) issued by the Norwegian Society forOil and Gas Measurement.

Based on the measured Reynolds number with the present invention, a morecorrect discharge coefficient can be calculated by the multiphase meter.Based on this new value of discharge coefficient, a more correctvelocity of the multiphase fluid can be determined which again can beused to calculate a more correct Reynolds number by the presentinvention. By continuing this iterative interaction between thecalculations of the present invention and the multiphase meter until themeasured Reynolds number has converged to a stable value (does notchange anymore), the Reynolds number and flow rate of the multiphasemixture has then been determined. The calculation can also be performedwithout iteration, but then the accuracy could be reduced.

By performing a second measurement which is suited to classify theliquid emulsion type as either oil or water continuous, it is alsopossible to determine the viscosity of the oil fraction. The WLR (waterliquid ratio) of the liquid fraction is measured by the multiphasemeter. When the WLR of the liquid fraction is known and the emulsion isoil continuous, the oil viscosity can easily be calculated using theequation relating the liquid viscosity to the oil viscosity, waterviscosity and WLR, as described in “A study of the performance ofVenturi meters in multiphase flow”, by Hall, Reader-Harris, andMillington, 2^(nd) North American Conference on Multiphase Technology.The effect of gas on the multiphase mixture can easily be accounted forby using the well-known Nissan-Grundberg equation, which relates theviscosity of a liquid/gas mixture to the mass fraction of the liquid andgas and the viscosity of the individual liquid and gas fractions. Whenthe viscosity of the oil fraction is known, it can be used to calculatethe amount of diluent injected into a heavy oil well stream, providedthat the viscosity of the heavy oil and diluent is known.

The uniqueness of the present invention is the ability to provide ameasurement of the Reynolds number of a multiphase mixture, which thencan be used to correct the flow rate measurements of a multiphase flowmeter in such a way that the multiphase flow meter is able to handle alarge variation in liquid viscosity range which are common for heavy oilflow conditions. The Reynolds number measurement is performed understable flow conditions (i.e. measurement is performed at the samedensity and velocity as in the multiphase meter) and does not rely onany mechanical vibrating devices. It is known that the recovery pressureof a venturi is related to the viscosity and density of the fluid in thepipe and therefore also the Reynolds number of the flow (e.g. U.S. Pat.No. 7,469,188). However, field experiments where the recovery pressureof a venturi together with measured multiphase mixture density has beenused to determine the viscosity and Reynolds number, has proven to benot successful. The main reason for this is that there are too manyparameters which are related to the recovery differential pressure, suchthat it is difficult to find an unambiguous solution for the multiphasefluid viscosity and Reynolds number. As an example, both the velocityand density of the fluid changes in the recovery section of the venturi,and the change in density and velocity may continue far beyond theoutlet of the venturi. This effect cannot be estimated or modeled easilyand makes it difficult to provide reliable calculations of the Reynoldsnumber. The present invention overcomes this problem since the fluiddensity and fluid velocity is not changing between the Reynolds sensorand the multiphase meter, since they have the same diameter and noobstructive element between them. A well defined solution for theReynolds number is ensured by that the relationships between Reynoldsnumber, differential pressure, and flow rate (velocity and density) arehighly different. In the Reynolds sensor, friction alone generates thedifferential pressure, while in the venturi it is a combination ofimpulse and friction.

Another uniqueness of the present invention is the ability to determinethe amount diluents mixed into a heavy oil well stream.

Yet another uniqueness of the present invention is that it works in anunprocessed well stream containing gas, water and other corrosivechemicals in addition to sand.

The invention will be further described in the following with referenceto the figures, where:

FIG. 1 shows a schematic longitudinal sectional view of a firstexemplified embodiment of an apparatus for measuring the Reynolds numberand correcting the flow rates of a differential pressure basedmultiphase meter according to the invention,

FIG. 2 shows a schematic longitudinal sectional view of a secondexemplified embodiment of an apparatus for measuring the Reynolds numberand correcting the flow rates of a differential pressure basedmultiphase meter according to the invention,

FIG. 3 shows a schematic longitudinal sectional view of a thirdexemplified embodiment of an apparatus for measuring the Reynolds numberand correcting the flow rates of a differential pressure basedmultiphase meter according to the invention,

FIG. 4 shows a schematic longitudinal sectional view of an exemplifiedembodiment of an apparatus for measuring the Reynolds number accordingto the invention,

FIG. 5 shows a schematic longitudinal sectional view of a firstexemplified embodiment of an apparatus for classifying the liquidemulsion type according to the invention,

FIG. 6 shows a schematic longitudinal sectional view of a secondexemplified embodiment of an apparatus for classifying the liquidemulsion type according to the invention,

FIG. 7 shows a schematic longitudinal sectional view of a thirdexemplified embodiment of an apparatus for classifying the liquidemulsion type according to the invention,

FIG. 8 shows a graph of the liquid viscosity of a oil continuous andwater continuous liquid emulsion,

FIG. 9 shows a graph of the dielectric constant (permittivity) for a oilcontinuous and water continuous liquid emulsion,

FIG. 10 shows a graph of the discharge coefficient of a venturi vs. theReynolds number,

FIG. 11 shows a graph of the liquid viscosity as a function of the waterfraction (WLR) for oil continuous and water continuous liquid emulsionand variation in the temperature,

FIG. 12 shows a graph of the measured loss versus frequency at oilcontinuous liquid emulsion of the apparatus of FIG. 5,

FIG. 13 shows a graph of the measured loss versus frequency at watercontinuous liquid emulsion of the apparatus of FIG. 5,

FIG. 14 shows a graph of an emulsion classification feature, derivedfrom the measured loss versus frequency of a water and oil continuousliquid emulsions of the apparatus of FIG. 5, against WLR for differentmultiphase flow regimes,

Below is a summary of the main elements involved in determining theReynolds number of the multiphase mixture and how it is used to correctthe flow rates of a multiphase flow meter. The main elements involved inclassifying the liquid emulsion are also described.

The present invention contains a tubular section 1 which contains asection with a high wall roughness 3. For simplicity, this section is inthe further description of the present invention referred to as the“Reynolds sensor”. The wall of the Reynolds sensor may have “saw-teeth”pattern as shown in FIG. 1, but any other mechanical design providing arough surface, such as large threads or rectangular rings 3 as shown inFIG. 2, may be used. The present invention also includes a multiphasemeter 2. The multiphase meter may be of any type, such as thosedescribed in the previous sections, which contains a differentialpressure based flow meter. The multiphase flow meter described in U.S.Pat. No. 7,624,652 is particularly suited for this purpose, and forsimplicity, this flow meter is used to exemplify the invention in thedescription below.

The device, or multiphase meter, also contains a temperature andpressure measurement for compensation purposes, but for simplicity thesedevices are omitted in the following discussions.

The pipe diameter of the Reynolds sensor shall have approximately thesame pipe diameter as the multiphase meter as indicated by the arrow 4′.Then, the velocity of the multiphase fluid in the Reynolds sensor willbe the same as the velocity in the multiphase meter as long as theReynolds sensor is placed immediately upstream or downstream themultiphase meter.

Tappings (5/6) for measurement of the differential pressure are locatedat both ends of the Reynolds sensor. A conventional differentialpressure transmitter 4 can be used to measure the pressure drop acrossthe Reynolds sensor.

Changes in an inviscid flow moving from Point A to Point B along a pipeare described by Bernoulli's equation,

$\begin{matrix}{h = {{z(x)} + \frac{p(x)}{\rho \; g} + \frac{V(x)}{2\; g}}} & {{Equation}\mspace{14mu} 2}\end{matrix}$

where p is the pressure, V is the average fluid velocity, ρ is the fluiddensity, z is the vertical distance between the dP tappings (5/6), and gis the gravity acceleration constant.

Bernoulli's equation states that the total head h along a streamline ofthe pipe (parameterized by x) remains constant. This means that velocityhead can be converted into gravity head and/or pressure head (orvice-versa), such that the total head h stays constant. No energy islost in such a flow.

For real viscous fluids, mechanical energy is converted into heat (inthe viscous boundary layer along the pipe walls) and is lost from theflow. Therefore one cannot use Bernoulli's principle of conserved head(or energy) to calculate flow parameters. Still, one can keep track ofthis lost head by introducing another term (called viscous head) intoBernoulli's equation to get,

$\begin{matrix}{h = {z + \frac{p}{\rho \; g} + \frac{V^{2}}{2\; g} + {\int_{x_{0}}^{x}{\frac{f}{D}\frac{{V\left( \overset{\sim}{x} \right)}^{2}}{2\; g}\ {\overset{\sim}{x}}}}}} & {{Equation}\mspace{14mu} 3}\end{matrix}$

where D is the pipe diameter. As the flow moves down the pipe, viscoushead slowly accumulates taking available head away from the pressure,gravity, and velocity heads. Still, the total head h (or energy) remainsconstant.

Since the pipe diameter of the Reynolds sensor is the same as the pipediameter of the multiphase meter, we then know that the fluid velocity Vis the same in the two cases (stays constant). With D and V constant wecan integrate the viscous head equation and solve for the pressure atPoint B (6),

$\begin{matrix}{p_{B} = {p_{A} - {\rho \; {g\left( {{\Delta \; z} + {f\frac{L}{D}\frac{V^{2}}{2\; g}}} \right)}}}} & {{Equation}\mspace{14mu} 4}\end{matrix}$

where L is the length of the Reynolds sensor, point A is the location ofthe first dP tapping (5) and point B is the location of the second dPtapping (6) and Δz is the change in pipe elevation between 5 and 6.

The viscous head term is scaled by the pipe friction factor f. Ingeneral, f depends on the Reynolds Number R of the pipe flow, and therelative roughness e/D of the pipe wall,

$\begin{matrix}{f = {f\left( {R,\frac{e}{D}} \right)}} & {{Equation}\mspace{14mu} 5}\end{matrix}$

The roughness measure e is the average size of the bumps on the pipewall. The relative roughness e/D is therefore the size of the bumpscompared to the diameter of the pipe. For commercial pipes this isusually a very small number. A perfectly smooth pipe would have aroughness of zero.

For laminar flow without any gas (R<2000 in pipes), f can be deducedanalytically, and the result is shown in equation 6 below:

$\begin{matrix}{f = \frac{64}{R}} & {{Equation}\mspace{14mu} 6}\end{matrix}$

However, when the wall roughness is large (e.g. greater than 0.05), theroughness of the wall will introduce turbulence in the flow and the flowwill therefore be turbulent for Reynolds numbers well below 2000. Whengas is presented in the multiphase flow, the flow will also behaveturbulent for very low Reynolds numbers, provided that the wallroughness is large enough.

In other words, the relative roughness e/D of the Reynolds sensor shouldbe designed such that turbulent flow is obtained for the multiphasefluid conditions the sensor is intended to be used for.

For turbulent flow, f can easily be determined from experimental curvefits. One such fit is provided by Colebrook (1938)—“Turbulent Flow inPipes”, Journal of the Inst. Civil Eng. (11), page 133” and shown inequation 7 below.

$\begin{matrix}{\frac{1}{\sqrt{f}} = {{- 2} \cdot {\log \left( {\frac{e/D}{3.7} + \frac{2.51}{R\sqrt{f}}} \right)}}} & {{Equation}\mspace{14mu} 7}\end{matrix}$

By measuring the pressure at point A(5) and point B(6), obtaining thevelocity of the multiphase mixture V and multiphase mixture density ρfrom the multiphase flow meter 2, the Reynolds number of the multiphasemixture can easily be calculated in a iterative fashion based onequation 7 and equation 4.

As an alternative, an experimental derived curve or equation relatingthe Reynolds number to the friction factor can be obtained by performingflow loop experiments with the Reynolds sensors for flow conditions withknown Reynolds numbers.

The Reynolds number of the multiphase fluid can then easily bedetermined by measuring the pressure at point A (5) and Point B (6) andusing equation 4 to calculate the friction factor. When the frictionfactor is known, the experimentally derived relation between thefriction factor and Reynolds number can be used to calculate theReynolds number of the multiphase mixture. In the further description ofthe present invention, this Reynolds number is referred to as the“measured Reynolds number”.

Based on the measured Reynolds number, an improved discharge coefficientfor the venturi (or any other differential pressure based flow meter)can be calculated. FIG. 10 shows a plot of the venturi dischargecoefficient 22 vs. Reynolds number 21 for a typical venturi. The datapoints 20 have been obtained experimentally in a flow loop. By making acurve fit to the experimental derived data points 20, an equationrelating the Venturi discharge coefficient to the measured Reynoldsnumber can be derived. This equation is then used to calculate animproved discharge coefficient based on the measured Reynolds number.Based on the improved discharge coefficient, an improved velocity of themultiphase mixture can be calculated, which again is used to calculatean improved friction factor and improved measured Reynolds number, whichagain is used to calculated an improved discharge coefficient of theventuri. This calculation process is repeated until the measuredReynolds number has converged to a stable value.

The method for measuring the Reynolds number and correcting the flowrate of the multiphase meter for variations in the Reynolds number canbe summarized in the following steps:

-   -   1) Use the venturi discharge coefficient from previous        calculation as starting value and calculate the velocity of the        multiphase mixture.    -   2) Calculate the measured friction factor of the Reynolds sensor        based on the velocity from step 1 together with measured        multiphase mixture density from the multiphase meter, measured        pressure drop across the Reynolds sensor and equation 4.    -   3) Use the experimentally derived relationship (curve) between        friction factor and Reynolds number of the Reynolds sensor to        calculate the measured Reynolds number    -   4) Use an experimentally derived relationship (curve) between        Reynolds number and venturi discharge curve to calculate a new        and improved value of the venturi discharge coefficient    -   5) Repeat step 1-5 until the measured Reynolds number (and        therefore also the discharge coefficient) has converged to a        stable value

Step 2 and 3 above can also be replaced by an iterative calculationbased on equation 4 and 7, however in practice an experimental derivedrelationship between the friction factor and Reynolds number asdescribed in step 2 and 3 will give the most accurate result.

FIG. 2 shows another preferred embodiment of the present invention wherethe roughness of the Reynolds sensor is made of rectangular rings orgrooves 3 in the wall surface. The inner diameter 4′ of the rectangularrings 3 is the same as the pipe diameter such that the velocity in theReynolds sensor is the same as the velocity in the pipe.

A more practical realization of the wall roughness is shown in FIG. 4where the roughness is made based on a combination of a saw-toothpattern and rectangular rings 3. This pattern is cost efficient tofabricate in a CNC operated machining bench.

Another way of increasing the pressure drop across the Reynolds sensoris to let its cross-sectional shape vary between its ends, e.g. fromcircular through rhombic and back to circular, while maintaining aconstant cross-sectional area at all points.

FIG. 3 shows another preferred embodiment of the present invention wherea second differential pressure transmitter 5′ is used to measure thepressure drop across a pipe section (7/8) of the same length as theReynolds sensor (5/6). The wall roughness of this pipe section shall below, and preferable the same value as the multiphase meter. Since thewall roughness of this section is low, the friction will also be low. Bycomparing the measured pressure drop across the Reynolds sensor 4 withthe pressure drop across a normal pipe section of the same length as theReynolds sensor, it is possible to obtain a differential measurement ofthe friction factor. In other words, based on this arrangement it ispossible to obtain a friction measurement which is relative to thefriction of the normal pipe (i.e. pipe of the multiphase meter). Thealgorithms for calculating the measured Reynolds number and correctingthe venturi discharge coefficient will be the same as describedpreviously, where the only modification is that the experimental curverelating the friction factor to the measured pressure drop of theReynolds sensor will be replaced with an experimental curve relating thefriction factor to the relative difference between the measurement at 4and 5′. Examples of suitable mathematical expressions for the relativedifference between 4 and 5′ are the ratio between 4 and 5′ or thedifference between 4 and 5′.

The present invention can also be extended with an emulsionclassification measurement to determine the viscosity of the oilfraction. An emulsion classification measurement is a measurement whichis suited to determine whether the liquid phase is oil or watercontinuous. Examples of devices suited to perform emulsionclassification measurement are shown in FIGS. 5, 6 and 7. A transmittingantenna 10 and receiving antenna 11 are located in a pipe 1. Thedistance between the antennas 10 and 11 may be from 1 to a few pipediameters. The antennas may be of any type suited for transmittingelectromagnetic energy into the pipe. A coaxial antenna is common way toachieve this. Since design of antennas are well known in prior art, itis not described any further.

By transmitting a broadband signal on antenna 10 and measuring thereceived power at antenna 11, the frequency response will be quitedifferent when the liquid phase is oil continuous vs. water continuous.FIG. 12 shows the received power 27/28 as a function of frequency 26when the liquid phase is oil continuous and FIG. 13 shows the receivedpower 27/28 as a function of frequency 26 when the liquid phase is watercontinuous.

For oil continuous liquid, the received power 27/28 is large at thehighest frequency and low at the lowest frequencies. For watercontinuous liquid emulsion, the power at the highest frequencies iscomparable to the power at the lowest frequencies. By calculating theaverage power in a low frequency band and average power in a highfrequency band and calculating the ratio between the average power inthese two band, a relative ratio of the high frequency power vs. the lowfrequency power can be obtained. This ratio is in this document referredto as the “Broadband loss ratio”.

FIG. 14 shows the measured Broadband loss ratio for oil continuousemulsions 33 and water continuous emulsions 32 for WLR range of 0-100%.The data has been obtained based on measurements in the MPM Multiphasetest flow loop for a gas fraction (GVF) in the range 0-99.9% and watersalinity in the range 0-1% NaCl. Since all these test points has beencollected with relative low water salinity where the difference betweenoil continuous and water continuous is less compared to highersalinities, it is considered as being a worst-case scenario for apractical multiphase meter. By comparing the measured Broadband lossratio vs an empirical derived threshold value 31, the emulsion isclassified as oil continuous if the Broadband loss ratio is below thethreshold value and water continuous if the measured Broadband lossratio is above the threshold value.

FIG. 6 and FIG. 7 shows other preferred arrangements for thetransmitting and receiving antennas, but in principle the antennas maybe located in any plane around the pipe circumference as long as thedistance between the antennas are in the range of one to a few pipediameters.

The measurement for performing the emulsion classification measurementmay be obtained from a separate device/sensor. For simplicity this isnot shown in any figures; however, this is considered to be obvious to aperson skilled in the art. Alternatively, it may be possible to realizethe emulsion classification measurement as a part of the multiphasemeter 2. The multiphase meter disclosed in U.S. Pat. No. 7,624,652 is anexample of a device well suited for this purpose since it contains atleast two antennas in the pipe in a similar manner as FIG. 5-7.

The method for determining the viscosity of the oil can then besummarized in the following steps:

-   -   1) Use the venturi discharge coefficient from previous        calculation as starting value and calculate the velocity of the        multiphase mixture.    -   2) Calculate the measured friction factor of the Reynolds sensor        based on the velocity from step 1 together with measured        multiphase mixture density from the multiphase meter, measured        pressure drop across the Reynolds sensor and equation 4.    -   3) Use the experimentally derived relationship (curve) between        friction factor and Reynolds number of the Reynolds sensor to        calculate the measured Reynolds number    -   4) Use an experimentally derived relationship (curve) between        Reynolds number and venturi discharge curve to calculate a new        and improved value of the venturi discharge coefficient    -   5) Repeat step 1-4 until the measured Reynolds number (and        therefore also the discharge coefficient) has converged to a        stable value    -   6) Calculated the multiphase viscosity based on the measured        Reynolds number, pipe diameter, measured multiphase mixture        density using equation 0.    -   7) Calculate the viscosity of the liquid phase. A Nissan        Grundberg type model together with the measured mass fraction of        liquid and gas from the multiphase meter can be used for this        purpose.    -   8) The emulsion type is classified by a separate classification        measurement. The classification measurement may be based on        measuring the Broadband loss ratio as described above and        comparing it to a empirically determined threshold. If the        BroadBand loss ratio is above the threshold, the emulsion is        classified as water continuous, and if it is below the        threshold, the liquid emulsion is classified as oil continuous.    -   9) The viscosity of water, and gas are calculated at present        temperature and pressure. The temperature and pressure is        measured using conventional transmitters mounted in the pipe.        Most flow meters, such as a multiphase flow meter, also contains        an integrated pressure and temperature transmitter. The        viscosity is typically calculated from a pressure and        temperature dependent look-up table which is generated in an        off-line PVT simulator such as PVTSim or Infochem.    -   10) If the liquid emulsion is classified as water continuous,        the previous value is used as oil viscosity (the viscosity can        only be calculated for oil continuous flow conditions)    -   11) If the liquid emulsion is classified as oil continuous, then        the oil viscosity is calculated based on the measured WLR,        measured liquid viscosity from step 7 and the viscosity for        water. Equation for calculating the oil viscosity based on the        measured WLR and liquid viscosity can be found in “A study of        the performance of Venturi meters in multiphase flow”, by Hall,        Reader-Harris, and Millington, 2^(nd) North American Conference        on Multiphase Technology.

It will be clear to the skilled person that the invention is not limitedto the exemplifying embodiments described in the above, but may bevaried and modified within the scope of the appended claims.

1. A method for determining the flow rates of a multi-component mixturein a pipe including a gas phase and a liquid phase, the methodcomprising the following steps: a. the flow rates of the individualcomponents of the multi-component mixture are measured, b. the Reynoldsnumber of the multi-component mixture is measured separately from theflow rate measurements, and c. based on the result from step a and b, amore accurate flow-rate of the individual components of themulti-component mixture is calculated.
 2. A method according to claim 1,wherein the said flow rates of the individual components of themulti-component mixture is measured using a multiphase flow meter.
 3. Amethod according to claim 2, wherein said multiphase flow meter containsone of a Venturi, V-cone and Dall-tube.
 4. A method according to claim1, wherein said Reynolds number is measured based on a measurement ofthe pressure drop across a pipe section with a large wall roughness. 5.A method according to claim 4, wherein said pipe section with large wallroughness has the same inner diameter as said multiphase flow meter. 6.A method according to claim 4, wherein an axial section through saidwall roughness has one of a saw-tooth pattern, square wave pattern andsinusoidal pattern.
 7. A method according to claim 1, wherein saidReynolds number is measured based on a ratio and/or difference between ameasurement of the pressure drop across a pipe section with a large wallroughness and the pressure drop across a pipe section with a small wallroughness.
 8. An apparatus for determining the flow rates of amulti-component mixture in a pipe, the apparatus comprising thefollowing elements: a. a flow meter for measuring the individualcomponents of the multi-component mixture b. means for measuring theReynolds number of the multi-component mixture c. a computer and amathematical program for calculating the Reynolds number ofsaid-component mixture and a mathematical program for calculating theflow rates of the individual components of said multi-component mixture.9. An apparatus according to claim 8, wherein the said flow-meter is amultiphase flow meter.
 10. An apparatus according to claim 9, whereinsaid multiphase flow meter contains one of a Venturi, V-cone andDall-tube.
 11. An apparatus according to claim 8, wherein said means formeasuring the Reynolds number contains a pipe section with a large wallroughness and a means for measuring the pressure drop across the pipesection with the large wall roughness.
 12. An apparatus according toclaim 11, wherein said pipe section with large wall roughness has thesame inner diameter as said multiphase flow meter.
 13. An apparatusaccording to claim 11, wherein an axial section through said wallroughness has one of a saw-tooth pattern, square wave pattern andsinusoidal pattern.
 14. An apparatus according to claim 8, wherein saidmeans for measuring the Reynolds number contains a pipe section with alarge wall roughness and a means for measuring the pressure drop acrossthe pipe section with the large wall roughness and a pipe section with asmall wall roughness and a means for measuring the pressure drop acrossthe pipe section with the small wall roughness.